The present invention relates generally to processes, methods, and computer software for calculating mass flow rates of gas and liquid phases of a multiphase flow. More particularly, the present invention relates to software which uses multiple pressure differentials to determine mass flow rates of gas and liquid phases of high void fraction multiphase flows.
There are many situations where it is desirable to monitor multiphase fluid streams prior to separation. For example, in oil well or gas well management, it is important to know the relative quantities of gas and liquid in a multiphase fluid stream, to thereby enable determination of the amount of gas, etc. actually obtained. This is of critical importance in situations, such as off-shore drilling, in which it is common for the production lines of several different companies to be tied into a common distribution line to carry the fuel back to shore. In the prior art, a common method for metering a gas is to separate out the liquid phase, but a separation system in not desirable for fiscal reasons. When multiple production lines feed into a common distribution line, it is important to know the flow rates from each production line to thereby provide an accurate accounting for the production facilities.
In recent years, the metering of multiphase fluid streams prior to separation has achieved increased attention. Significant progress has been made in the metering of multiphase fluids by first homogenizing the flow in a mixer then metering the pseudo single phase fluid in a venturi in concert with a gamma densitometer or similar device. This approach relies on the successful creation of a homogenous mixture with equal phase velocities, which behaves as if it were a single phase fluid with mixture density:
{overscore (xcfx81)}=xcex1xcfx81g+(1xe2x88x92xcex1)xcfx81l
where xcex1 is the volume fraction of the gas phase, xcfx81g is the gas phase density and xcfx81l is the liquid phase density. This technique works well for flows which after homogenizing the continuous phase is a liquid phase. While the upper limit of applicability of this approach is ill defined, it is generally agreed that for void fractions greater than about ninety to ninety-five percent (90-95%) a homogenous mixture is very difficult to create or sustain.
The characteristic unhomogenized flow in this void fraction range is that of an annular or ring-shaped flow configuration. The gas phase flows in the center of the channel and the liquid phase adheres to and travels along the sidewall of the conduit as a thick film. Depending on the relative flow rates of each phase, significant amounts of the denser liquid phase may also become entrained in the gas phase and be conveyed as dispersed droplets. Nonetheless, a liquid film is always present on the wall of the conduit. While the liquid generally occupies less than five percent (5%) of the cross-sectional volume of the flow channel, the mass flow rate of the liquid phase may be comparable to or even several times greater than that of the gas phase due to its greater density.
The fact that the gas and liquid phases are partially or fully separated, and consequently have phase velocities which are significantly different (slip), is problematic where metering of the respective mass flow rates of the gas and liquid phases is concerned. In particular, the presence of the liquid phase distorts the gas phase mass flow rate measurements and causes conventional meters, such as orifice plates and venturi meters, to overestimate the mass flow rate of the gas phase. For example the gas phase mass flow rate can be estimated using the standard equation:       m    g    =                    A        ⁢                  xe2x80x83                ⁢                  C          c                ⁢        Y                              1          -                      β            4                                ⁢                  2        ⁢                  ρ          g                ⁢        Δ        ⁢                  xe2x80x83                ⁢        P            
where mg is the gas phase mass flow rate, A is the area of the throat, xcex94P is the measured pressure differential, xcfx81g the gas phase density at flow conditions, Cc the discharge coefficient, and Y is the expansion factor. In test samples having void fractions ranging from 0.997 to 0.95, the error in the measured gas phase mass flow rate ranges from about seven percent (7%) to about thirty percent (30%). It is important to note that the presence of the liquid phase increases the pressure drop in the venturi and results in over-predicting the true gas phase mass flow rate. This pressure drop is caused by the interaction between the gas and liquid phases.
In particular, liquid droplet acceleration by the gas, irreversible drag force work done by the gas phase in accelerating the liquid film, and wall losses, determine the magnitude of the observed pressure drop. In addition, the flow is complicated by the continuous entrainment of liquid into the gas phase, the redeposition of liquid from the gas phase into the liquid film along the venturi length, and also by the presence of surface waves on the surface of the annular or ringed liquid phase film. The surface waves on the liquid create a roughened surface over which the gas must flow, thereby increasing the momentum loss due to the addition of drag at the liquid/gas interface.
Other simple solutions have been proposed to solve the overestimation of gas mass flow rate under multiphase conditions. For example, Murdock ignores any interaction (momentum exchange) between the gas and liquid phases and has proposed to calculate the gas mass flow if the ratio of gas to liquid mass flow is known in advance. See Murdock, J. W. (1962), Two Phase Flow Measurement with Orifices, ASME Journal of Basic Engineering, December, pp. 419-433. Unfortunately this method still has up to a twenty percent (20%) error rate or higher.
Another example of a multiphase measurement device in the prior art is U.S. Pat. No. 5,461,930, (Farchi et al.), which appears to teach the use of a water cut meter and a volumetric flow meter for measuring the gas and liquid phases. This invention is complicated because it requires the use of a positive displacement device to measure the liquid and gas flow rates so it can avoid the problem of slip between the gas and liquid phases. This system does not appear to be effective for liquid fractions below about five percent to about ten percent (5%-10%). As mentioned earlier, other such prior art systems such as U.S. Pat. No. 5,400,657 (Kolpak et al.), are only effective for multiphase fluid flows where the gas fraction is twenty five percent (25%) of the volume and the liquid is seventy five percent (75%) of the volume.
Other volumetric measuring devices such as are indicated in U.S. Pat. No. 4,231,262 (Boll et al.), measure a flow of solids in a gas stream. For example, coal dust in a nitrogen stream may be measured. Although these types of devices use pressure measuring structures, they are not able to address the problem of measuring a liquid fraction in a multiphase flow where the liquid phase is less than ten percent (10%) or even five percent (5%) of the overall volume. Measuring liquid and gas phases of a multiphase flow is significantly different from measuring a gas having a solid particulate. The mass of the liquid is significant and not uniform throughout the gas. Incorrectly measuring the liquid throws off the overall measurements significantly. Furthermore, such devices, which typically have two pressure measuring points on the venturi throat, are not sensitive to the fact that a pressure drop is caused by the interaction between the gas and liquid phases and must be calculated for accordingly.
While past attempts at metering multiphase fluid streams have produced acceptable results below the ninety to ninety five percent (90-95%) void fraction range, they have not provided satisfactory metering for the very high void multiphase flows which have less than five to ten percent (5-10%) non-gas phase by volume. When discussing large amounts of natural gas or other fuel, even a few percentage points difference in the amount of non-gas phase can mean substantial differences in the value of a production facility.
For example, if there are two wells which produce equal amounts of natural gas per day. The first well produces, by volume, one percent (1%) liquid and the second well produces five percent (5%) liquid. If a conventional mass flow rate meter is relied upon to determine the amount of gas produced, the second well will erroneously appear to produce as much as twenty to thirty percent (20-30%) more gas than the first well. Suppose further that the liquid produced is a light hydrocarbon liquid (e.g., a gas condensate such as butane or propane) which is valuable in addition to the natural gas produced. Conventional meters will provide no information about the amount of liquid produced. Then, if the amount of liquid produced is equally divided between the two wells, the value of the production from the first well will be overestimated while the production from the second well will be underestimated.
To properly value the gas and liquid production from both wells, a method of more accurately determining the mass flow rate of both the gas and liquid phases is required. The prior art, however, has been incapable of accurately metering the very high void multiphase fluid streams. In light of the problems of the prior art, there is a need for methods, systems, and software that are relatively simple in design and operation and provide for increased accuracy in determining gas and liquid phase mass flow rates in multiphase fluid streams, particularly high void fraction multiphase fluid streams. Further, such methods, systems, and software should provide accurate results without requiring special treatment or manipulation, such as homogenization or separation, of the multiphase fluid. Finally, such methods, systems, and software should be reliable, simple to use, accurate, and relatively inexpensive.
The present invention has been developed in response to the current state of the art, and in particular, in response to these and other problems and needs that have not been fully or completely resolved. Briefly summarized, embodiments of the present invention provide for program code, executable code, and the like, that employs differential pressure data to calculate the respective mass flow rates of gas and liquid phases of a multiphase flow.
Embodiments of the present invention are especially well suited for use in measuring respective mass flow rates of gas and liquid phases of high void fraction multiphase flows such as are typically encountered in oil and gas field applications. However, it will be appreciated that embodiments of the present invention may be profitably employed in any application where it is desired to accurately and reliably measure mass flow rates of gas and liquid phases of a multiphase flow.
These, and other, features and advantages of the invention are realized in multiphase flow calculation (MFC) software for determining the respective mass flow rates of gas and liquid phases of a multiple phase fluid. In one embodiment of the invention, the MFC software resides on a client computer that is, preferably, in communication with various sensors, devices systems, and the like which provide input to the client computer concerning various aspects of a multiphase flow. Other inputs provided to the MFC software comprise given values of particular parameters or constants, preferably retrievably stored in the memory of the client computer. Finally, at least some parameter values determined by the a MFC software are employed as inputs in the determination of other parameter values, to provide input to a control system, and/or to provide feedback to a system operator or manager regarding various aspects of the multiphase flow.
Examples of given inputs typically employed by embodiments of the MFC software include, but are not limited to, a reference gas density rhog, preferably the density of methane at standard temperature and pressure, pressure differentials xcex94P2 and xcex94P3, typically provided by a differential pressure flowmeter or the like, a density rhol of the liquid phase, experimentally determined constants A, B, and C, and various inputs relating to the physical configuration of the differential pressure flowmeter. Such differential pressure flowmeter related inputs include a contraction ratio xcex2 of the area At, of the extended throat of the differential pressure flowmeter to the entrance area A0 of the differential pressure flowmeter, the temperature T of the multiphase flow at the entrance of the differential pressure flowmeter, and the pressure P of the multiphase flow at the entrance of the differential pressure flowmeter.
As suggested above, the given inputs to the MFC software originate from various sources. Typically, a differential pressure flowmeter, or the like, serves to provide pressure differentials xcex94P2 and xcex94P3 to the client computer by way of pressure transducers or the like. The temperature T and the pressure P of the multiphase flow at the entrance of the differential pressure flowmeter are provided by suitable temperature and pressure gauges, respectively, in communication with the client computer in which the MFC software resides. Further, given inputs such as reference gas density rhog, density rhol of the liquid phase, and experimentally determined constants A, B, and C, are stored in a database or other suitable data structure resident on, or accessible by, the client computer.
In operation, the given inputs, as well as values determined by the MFC software are then used by one or more modules of the MFC software to determine various parameters of interest concerning the multiphase flow. Such parameters determined by the MFC software modules include, but are not limited to, gas phase density rhogw, normalized gas phase mass flow rate mgm, actual gas phase mass flow rate mg, gas phase velocity ug, gas phase pressure drop xcex94Pgl3, liquid phase velocity ul, friction f, and multiphase flow mass flow rate mt. Once determined, such parameters are preferably used as inputs to other software programs, control systems such as may be used to control and adjust the performance of a gas or oil well from which the multiphase flow originates, feedback systems, or the like. Additionally, such values are preferably stored in a database for use in subsequent analyses and the like.
These and other features and advantages of the present invention will become more fully apparent from the following description and appended claims, or may be learned by the practice of the invention as set forth hereinafter.